Energy markets need a more effective credit management and clearing solution to address the structural problems in the marketplace and satisfy more stringent regulatory oversight. Many bilateral energy transactions are over-collateralized. Liquidity for forward contracts, a type of commercial merchandizing transaction, is dropping. Trading activity is shifting from forward contract markets to the spot markets due to differences in collateral practices. This shift puts greater credit risks on physical market participants operating within an area coordinated by an independent transmission provider (ITP) or a gas pipeline. Also, due to the Sarbanes-Oxley Act of 2002, participants must fully disclose all material risks including potential credit exposures and valuations of open forward-market positions.
The federal regulatory agency responsible for overseeing energy markets, the Federal Regulatory Energy Commission, (FERC), 888 First Street, N.E., Washington, D.C. 20426, and the federal regulatory agency responsible for overseeing energy futures markets, the Commodity Futures Trading Commission (CFTC), Three Lafayette Centre, 1155 21st Street, NW, Washington D.C. 20581, are increasingly investigating the cash and derivatives markets trading activity. In February 2003, the FERC and CFTC held a joint conference on “Credit Issues in the Energy Markets: Clearing and Other Solutions” to address the credit problems facing the energy industry. In January 2003, the FERC staff issued a report “Commission Use of Natural Gas Price Indices” describing specific instances of trade price reporting abuses. The FERC and CFTC continue to aggressively pursue market participants who attempt to manipulate the market or falsely report their activities.
The energy markets can be categorized into cash markets and derivative markets. Cash markets are wholesale markets in which commercial parties buy and sell energy by entering into bi-lateral spot and forward contracts with one another. The parties to cash market transactions intend to make and take delivery of the commodity at the specified time and title transfer routinely occurs. Derivative markets, in contrast, are not intended to serve as merchandizing channels for the actual purchase and sale of a commodity; rather, derivatives—such as swap agreements or exchange-traded futures contracts—are principally used by market participants for risk management or speculation. Although a derivative contract may call for physical delivery of a commodity at a future date, delivery does not routinely occur. Many of the commercial interests who trade in the energy cash markets also trade energy-related derivatives to hedge the price or other risks associated with their cash market transactions or other business activities.
The cash energy markets can be categorized by tenor (contract length) into spot markets and forward markets. Spot contracts typically require the commodity to be delivered immediately or in the near future, whereas forward contracts typically require the commodity to be delivered at a specified time further in the future. Industry practice for delineating between spot versus forward markets can vary from commodity to commodity. For example, spot markets for natural gas are operated on a time scale from next day delivery to next month delivery. Spot electricity transactions range from next hour delivery to next day delivery.
There is no single cash marketplace for energy. Cash markets can operate wherever the infrastructure exists to conduct the transactions. That infrastructure can take different forms. ITPs provide electronic Internet-based systems that allow buyers and sellers to transact with one another anonymously in a centralized venue where trading occurs under auction market or stock-market style bidding procedures. Once the transaction is confirmed the parties are identified. Over-the-counter (OTC) markets in which individual brokers match buyers and sellers into bilateral contracts operate in parallel to the ITP-sponsored markets.
Cash market transactions are delivered by scheduling contractual volumes through the delivery provider. For natural gas, the delivery provider is the pipeline operator. Gas pipeline operators typically only operate markets for transportation services to move the commodity from the point of receipt to the point of delivery. Pipeline operators also offer pooled scheduling points to facilitate title transfer between buyer and seller.
For electricity, the delivery provider is either a control area operator (CAO) (for example, Cinergy Corp., 139 East Fourth Street, Cincinnati, Ohio 45202), or an ITP. An ITP coordinates the movement of electricity over transmission grids. It can be either a regional transmission organization (RTO) (for example, the PJM market, Valley Forge, Pennsylvania, covering all or parts of Delaware, Maryland, New Jersey, Ohio, Pennsylvania, Virginia, West Virginia and the District of Columbia) or an independent system operator (ISO) (for example, California ISO, P.O. Box 639014, Folsom, Calif. 95763-9014. covering California and other western states). In addition to operating markets for transmission services, ITPs may operate other markets. For example, PJM also operates a capacity market, a day-ahead spot energy market, an hour-ahead spot energy market, a regulation market and a spinning reserves market. These markets help to ensure that physical buyers such as electric utilities have access to products at competitive market prices to support the operational requirements of their business and help maintain the overall reliability and integrity of the transmission grid. The ITPs manage the operation, clearing, scheduling, settlement and billing for these markets.
In the cash markets for energy, the purchaser under a spot or forward contract is normally required to pay for the commodity after it has taken delivery. If the purchaser receives the commodity within a given month under multiple spot and/or forward transactions with a single seller, as is often the case, the purchaser would make a single payment to the seller approximately twenty (20) calendar days for electricity and twenty-five (25) calendar days for natural gas after the month end for the total amount that it received from the seller that month. For electricity, for example, this means that the purchaser has approximately six weeks to pay for commodity it received during the first week of a given month, five weeks to pay for commodity received the second week, etc. Although gas pipelines and ITPs have similar payment cycles, the amount of exposure from non-payment is greater for ITPs than for pipelines due to the number of markets an ITP operates.
Company downgrades by credit rating agencies combined with long post-delivery payment cycles have forced changes in credit and collateralization practices among market participants in the bilateral markets. Participants below investment grade when acting as buyers are often required to post the full notional value of an open (that is, pre-delivery) the contract plus any potential mark-to-market exposure in the event the contract needs to be liquidated. Sellers also may be required to post collateral if the market price has moved against the contracted price prior to making delivery of the underlying commodity.
Collateral requirements can be further compounded for participants who transact in multiple markets. For example, a producer of electricity who buys natural gas as fuel for his plant may be required to post collateral equal to the full notional value of a monthly gas contract. That producer will likely be a seller of electricity. Since electricity is a unique commodity in that it is ‘instantly perishable’ and cannot be stored, the seller cannot claim a lien against the commodity it has delivered, as it might in merchandizing transactions for storable commodities. The delayed payment cycle under cash contracts creates a post-delivery credit risk for the seller that the power purchaser may default on its obligation to pay for electricity it has already received and used. The increased gas collateral requirement combined with the delayed payment cycle for sales of electricity create greater cash flow challenges for the power producer/seller.
Increasing volumes transacted through cash markets create a credit risk cycle. Credit downgrades increase the probability of counterparty default and increase the risk that, during a default event, replacement of non-delivered commodity would occur during periods of high prices due to market scarcity or uncertainty. These risks become internalized through higher forward energy prices as more market participants fall below investment grade. To avoid these forward price risk premiums and the additional collateral required to carry an open cash contract to delivery, participants lean on the shorter term markets operated by the ITPs.
The ITPs are not as responsive in adjusting their credit policies and practices due to the time consuming and uncertain process of obtaining stakeholder consensus and regulatory approvals. In the event of a default within an ITP market, the loss is spread to all of the ITP participants through an allocation methodology prescribed in FERC approved tariffs. While participants may know the percentage of loss that would be allocated to them in the event of a default, they do not know the amount of potential exposure.
The Sarbanes-Oxley Act of 2002 requires full disclosure of any item that may have a material current or future effect on the financial condition of the company. Payment default within an ITP can be material not only for the ITP but also for the market participants transacting within the ITP who must absorb the loss. In 2001, two PJM market participants defaulted on payments totaling $4.1 million. At the extreme, a confluence of events occurred in 2001 that forced the largest two utilities in California to default on billions of dollars of payments and one of them to declare bankruptcy.
Another important aspect of financial reporting for companies that trade commodities is the market value of their open positions and their profit or loss resulting from posted settlement prices. In bilateral trading relationships within the energy markets, market and settlement prices are determined by independent surveys to establish price indices. These indices are used to value “open” forward contracts, that is, pre-delivery forward contracts, and may also be used as pricing references for energy-related derivatives transactions. Investigations by the FERC and the CFTC have identified instances of alleged false and fraudulent reporting of prices to the independent surveyors. Regulators also are seeking ways to ensure the integrity of price indices through proper and accurate reporting.
OTC brokers also will report to their clients the range of price activity in the forward markets based upon the volumes of trades occurring within their firm. Market participants will combine the price information received from several brokers to establish a forward price curve with which to value their open positions. As less trade volume occurs in the forward market and the tenor of trade activity decreases, the ability to accurately mark-to-market and report true value of open commodity positions in financial statements becomes increasingly difficult.
What is thus needed is a credit management and clearing platform for energy markets that reduces credit and default risk, reduces cash collateral requirements, reduces net energy costs while avoiding cost impacts on net buyers, insulates system reliability operations from financial distress, restores liquidity to forward markets, and provides reliable price indices.